Securities registered pursuant to Section 12(g) of the Act:None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:None

Indicate the number of outstanding shares of each of the Registrant’s classes of capital or common stock as of the close of the period covered by the annual report:
163,753,87436,509,953 common shares as at December 31, 2015 and April 24, 201420, 2016

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [  ]     No [X]

If this report is an annual or transition report, indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Yes [  ]     No [X]

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X]     No [  ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [X]Yes[X]     No [  ]

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer     [  ]       Accelerated filer    [  ]       Non-accelerated filer [X]

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow:

Item 17 [  ]          Item 18 [  ] 

If this is an annual report, indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [  ]     No [X]

TABLE OF CONTENTS

GENERAL INFORMATION

All references in this annual report on Form 20-F to the terms “we”, “our”, “us”, “the Company” and “Dejour”“DXI Energy” refer to DejourDXI Energy Inc.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This annual report on Form 20-F and the documents incorporated herein by reference contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements concern our anticipated results and developments in our operations in future periods, planned exploration and, if warranted, development of our properties, plans related to our business and other matters that may occur in the future. These statements relate to analyses and other information that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.

Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “expects” or “does not expect”, “is expected”, “anticipates” or “does not anticipate”, “plans”, “estimates” or “intends”, or stating that certain actions, events or results “may”, “could”, “would”, “might” or “will” be taken, occur or be achieved) are not statements of historical fact and may be forward-looking statements. The forward-looking statements contained in this annual report on Form 20-F concern, among other things:

• drilling inventory, drilling plans and timing of drilling, re-completion and tie-in of wells;

• productive capacity of wells, anticipated or expected production rates and anticipated dates of commencement of production;

• drilling, completion and facilities costs;

• results of our various projects;

• ability to lower cost structure in certain of our projects;

• our growth expectations;

• timing of development of undeveloped reserves;

• the performance and characteristics of the Company’s oil and natural gas properties;

• oil and natural gas production levels;

• the quantity of oil and natural gas reserves;

• capital expenditure programs;

• supply and demand for oil and natural gas and commodity prices;

• the impact of federal, provincial, and state governmental regulation on Dejour;

• expected levels of royalty rates, operating costs, general administrative costs, costs of services and other costs and expenses;

• expectations regarding our ability to raise capital and to continually add to reserves through acquisitions, exploration and development;

• treatment under governmental regulatory regimes and tax laws; and

• realization of the anticipated benefits of acquisitions and dispositions.

These statements relate to analyses and other information that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of our management.

4

Forward-looking statements are subject to a variety of known and unknown risks, uncertainties and other factors that could cause actual events or results to differ from those expressed or implied by the forward-looking statements, including, without limitation:

• risks related to the marketability and price of oil and natural gas being affected by factors outside our control;

• risks related to world oil and natural gas prices being quoted in U.S. dollars and our production revenues being adversely affected by an appreciation in the Canadian dollar;

• risks related to our ability to execute projects being dependent on factors outside our control;

• risks related to oil and gas exploration having a high degree of risk and exploration efforts failing;

• risks related to cumulative unsuccessful exploration efforts;

• risks related to oil and natural gas operations involving hazards and operational risks;

• risks related to seasonal factors and unexpected weather;

• risks related to competition in the oil and gas industry;

• risks related to the fact that we do not control all of the assets that are used in the operation of our business;

• risks related to our ability to market oil and natural gas depending on its ability to transport the product to market;

• risks related to high demand for drilling equipment;

• risks related to title to our properties;

• risks related to our ability to continue to meet its oil and gas lease or license obligations;

• risks related to our anticipated substantial capital needs for future oil and gas exploration, development and acquisitions;

• risks related to our cash flow from reserves not being sufficient to fund its ongoing operations;

• risks related to covenants in issued debt restricting the ability to conduct future financings;

• risks related to renewal or refinancing;

• risks related to our being exposed to third party credit risks;

• risks related to our being able to find, acquire, develop and commercially produce oil and natural gas;

• risks related to our properties not producing as projected;

• risks related to our estimated reserves being based upon estimates;

• risks related to future oil and gas revenues not resulting in revenue increases;

• risks related to our managing growth;

• risks related to our being dependent on key personnel;

• risks related to our operations being subject to federal, state, local and other laws, controls and regulations;

• risks related to uncertainty regarding claims of title and right of aboriginal people;

• risks related to environmental laws and regulations;

• risks related to our facilities, operations and activities emitting greenhouse gases;

• risks related to our not having paid dividends to date;

• risks related to our stock price being volatile; and

• risks related to our being a foreign private issuer.

5

This list is not exhaustive of the factors that may affect any of our forward-looking statements. Some of the important risks and uncertainties that could affect forward-looking statements are described further under the section heading “Item 3. Key Information – D. Risk Factors” below. If one or more of these risks or uncertainties materializes, or if underlying assumptions prove incorrect, our actual results may vary materially from those expected, estimated or projected. Forward-looking statements in this document are not a prediction of future events or circumstances, and those future events or circumstances may not occur. Given these uncertainties, users of the information included herein, including investors and prospective investors are cautioned not to place undue reliance on such forward-looking statements. Investors should consult our quarterly and annual filings with Canadian and U.S. securities commissions for additional information on risks and uncertainties relating to forward-looking statements. We do not assume responsibility for the accuracy and completeness of these statements.

Forward-looking statements are based on our beliefs, opinions and expectations at the time they are made, and we do not assume any obligation to update our forward-looking statements if those beliefs, opinions, or expectations, or other circumstances, should change, except as required by applicable law.

We qualify all the forward-looking statements contained in this annual report on Form 20-F by the foregoing cautionary statements.

CURRENCY AND EXCHANGE RATES

Canadian Dollars Per U.S. Dollar

Unless otherwise indicated, all references in this annual report are to Canadian dollars ("$" or "Cdn$"). Certain numbers in this annual report are rounded to the nearest thousands of Canadian dollars.

The following tables set forth the number of Canadian dollars required to buy one United States dollar (US$) based on the average, high and low nominal noon exchange rate as reported by the Bank of Canada for each of the last five fiscal years and each of the last six months. The average rate means the average of the exchange rates on the last day of each month during the period.

Exchange rates are based on the Bank of Canada nominal noon exchange rates. The nominal noon exchange rate on April 24, 201420, 2016 as reported by the Bank of Canada for the conversion of United States dollars into Canadian dollars was US$1.00 = Cdn$1.1027.1.2650.

ABBREVIATIONS

6

7

PART I

Our selected financial data and the information in the following tables for the years ended December 31, 2009 - 20132011 – 2015 was derived from our audited consolidated financial statements. These audited consolidated financial statements have been audited by BDO Canada LLP, Chartered Accountants, for the years ended December 31, 2015, 2014, 2013, 2012, 2011 and 2010, and Dale Matheson Carr-Hilton LaBonte LLP, Chartered Accountants, for the year ended December 31, 2009.2011. Certain prior years’ comparative figures have been reclassified, if necessary.

The information in the following table should be read in conjunction with the information appearing under the heading “Item 5. Operating and Financial Review and Prospects” and our audited consolidated financial statements under the heading "Item 18. Financial Statements".

On January 1, 2011, the Company adopted International Financial Reporting Standards (“IFRS”) for financial reporting purposes, using a transition date of January 1, 2010. The Company’s annual audited Consolidated Financial Statements for the year ended December 31, 2011, including 2010 required comparative information, have been prepared in accordance with IFRS, as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”). Financial statements prior to the fiscal year ended December 31, 2010 were prepared in accordance with pre-changeover Canadian generally accepted accounting principles (“Canadian GAAP”).

Financial information included in this annual report on Form 20-F for the years 2013, 2012, 2011 and 2010 is determined using IFRS, which differ from U.S. GAAP and Canadian GAAP. Unless otherwise indicated, financial information included in this annual report on Form 20-F prior to year 2010 were in accordance with Canadian GAAP.

We have not declared any dividends since incorporation and do not anticipate that we will do so in the foreseeable future. Our present policy is to retain all available funds for use in our operations and the expansion of our business.

8

The following table is a summary of selected audited consolidated financial information of the Company for each of the four most recently completed financial years. The information presented is presented in accordance with IFRS:

The following table is a summary of selected audited consolidated financial information of the Company for the fiscal year ended December 31, 2009. The information presented is presented in accordance with Canadian GAAP and is not comparable to the financial information presented in accordance with IFRS.

98

Canadian GAAP Adjusted to United States Generally Accepted Accounting Principles

Under U.S. GAAP the following financial information would be adjusted from Canadian GAAP, and certain prior years’ comparative figures have been reclassified or restated, if necessary. The following table is a summary of selected audited consolidated financial information of the Company for the fiscal year ended December 31, 2009. The information presented is in accordance with U.S. GAAP:

Exchange Rate History

See the disclosure under the heading "Currency and Exchange Rates" above.

Recently AdoptedAdoption of New and Amended Accounting Policies and Future Accounting PronouncementsStandards

IFRS

OnThe Company applied for the first time certain amendments, which are effective for annual periods beginning on or after January 1, 2011, we2015. The Company has not early adopted IFRS andany other standard, interpretation or amendment that has been issued but is not yet effective.

Although these amendments were applied for the accounting policiesfirst time in 2015, they did not have been applied in preparinga material impact on the annual consolidated financial statements for the years ended December 31, 2013, 2012 and 2011. The detail accounting policies in accordance with IFRS were disclosed in Note 3 of the Company’s audited consolidated financial statements.Company.

Not Applicable.

Not Applicable.

D. Risk Factors

10

An investment in a company engaged in oil and gas exploration involves an unusually high amount of risk, both unknown and known, present and potential, including, but not limited to the risks enumerated below. An investment in our common shares is highly speculative and subject to a number of known and unknown risks. Only those persons who can bear the risk of the entire loss of their investment should purchase our securities. An investor should carefully consider the risks described below and the other information that we file with the SEC and with Canadian securities regulators before investing in our common shares. The risks described below are not the only ones faced. Additional risks that we are not currently aware of or that we currently believe are immaterial may become important factors that affect our business. The risk factors set forth below and elsewhere in this annual report, and the risks discussed in our other filings with the SEC and Canadian securities regulators, may have a significant impact on our business, financial condition and/or results of operations and could cause actual results to differ materially from those projected in any forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements”.

Our failure to successfully address the risks and uncertainties described below would have a material adverse effect on our business, financial condition and/or results of operations, and the trading price of our common stock may decline and investors may lose all or part of their investment. We cannot assure you that we will successfully address these risks or other unknown risks that may affect our business.

Risks related to commodity price fluctuations

The marketability and price of oil and natural gas are affected by numerous factors outside of our control. Material fluctuations in oil and natural gas prices could adversely affect our net production revenue and oil and natural gas operations.

Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

• the domestic and foreign supply of and demand for oil and natural gas;
• the price and quantity of imports of crude oil and natural gas;
• overall domestic and global economic conditions;
• political and economic conditions in other oil and natural gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
• the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
• the level of consumer product demand;
• weather conditions;
• the impact of the U.S. dollar exchange rates on oil and natural gas prices; and
• the price and availability of alternative fuels.

9

Our ability to market our oil and natural gas depends upon our ability to acquire space on pipelines that deliver such commodities to commercial markets. We are also affected by deliverability uncertainties related to the proximity of our reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and facilities, as well as extensive governmental regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.

Both oil and natural gas prices are unstable and are subject to fluctuation. Any material decline in prices could result in a reduction of our net production revenue. The economics of producing from some wells may change as a result of lower prices, which could result in reduced production of oil or natural gas and a reduction in the volumes and net present value of our reserves. We might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in our net production revenue and a reduction in our oil and natural gas acquisition, development and exploration activities.

Because world oil and natural gas prices are quoted in U.S. dollars, our production revenues could be adversely affected by an appreciation of the Canadian dollar.

11

World oil and natural gas prices are quoted in U.S. dollars, and the price received by Canadian producers, including us, is therefore affected by the Canadian/U.S. dollar exchange rate, which will fluctuate over time. In recent years, the Canadian dollar has increased materially in value against the U.S. dollar, which may negatively affect our production revenues. Further material increases in the value of the Canadian dollar would exacerbate this potential negative effect and could have a material adverse effect on our financial condition and results of operations. An increase in the exchange rate for the Canadian dollar and future Canadian/U.S. exchange rates could also negatively affect the future value of our reserves as determined by independent petroleum reserve engineers.

Risks related to operating an exploration, development and production company

Our ability to execute projects will depend on certain factors outside of our control. If we are unable to execute projects on time, on budget or at all, we may not be able to effectively market the oil and natural gas that we produce.

We manage a variety of small and large projects in the conduct of our business. Our ability to execute projects and market oil and natural gas will depend upon numerous factors beyond our control, including:

• the availability of adequate financing;
• the availability of processing capacity;
• the availability and proximity of pipeline capacity;
• the availability of storage capacity;
• the supply of and demand for oil and natural gas;
• the availability of alternative fuel sources;
• the effects of inclement weather;
• the availability of drilling and related equipment;
• accidental events;
• currency fluctuations;
• changes in governmental regulations; and
• the availability and productivity of skilled labor.

Because of these factors, we could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that we produce.

Oil and gas exploration has a high degree of risk and our exploration efforts may be unsuccessful, which would have a negative effect on our operations.

10

There is no certainty that the expenditures to be made by us in the exploration of our current projects, or any additional project interests we may acquire, will result in discoveries of recoverable oil and gas in commercial quantities. An exploration project may not result in the discovery of commercially recoverable reserves and the level of recovery of hydrocarbons from a property may not be a commercially recoverable (or viable) reserve that can be legally and economically exploited. If exploration is unsuccessful and no commercially recoverable reserves are defined, we would be required to evaluate and acquire additional projects that would require additional capital, or we would have to cease operations altogether.

Cumulative unsuccessful exploration efforts could result in us having to cease operations.

The expenditures to be made by us in the exploration of our properties may not result in discoveries of oil and natural gas in commercial quantities. Many exploration projects do not result in the discovery of commercially recoverable oil and gas deposits, and this occurrence could ultimately result in us having to cease operations.

Oil and natural gas operations involve many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, our business, financial condition, results of operations and prospects could be adversely affected.

Our involvement in the oil and natural gas exploration, development and production business subjects us to all of the risks and hazards typically associated with those types of operations, including hazards such as fire, explosion, blowouts, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or personal injury. In particular, we may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property, and may necessitate an evacuation of populated areas, all of which could result in liability to us. In accordance with industry practice, we are not fully insured against all of these risks. Although we maintain liability insurance in an amount that we consider consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect upon our business, financial condition, results of operations and prospects. In addition, the risks we face are not, in all circumstances, insurable and, in certain circumstances, we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. For instance, we do not have insurance to protect against the risk from terrorism. Oil and natural gas production operations are also subject to all of the risks typically associated with those operations, including encountering unexpected geologic formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks could have a material adverse effect on our business, financial condition, results of operations and prospects.

12

Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity.

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Oil and natural gas development activities, including seismic and drilling programs in northern Alberta and British Columbia, are restricted to those months of the year when the ground is frozen. Wet weather and spring thaw may make the ground unstable. Although not as prevalent, such conditions sometimes prevail in the Rocky Mountains of Colorado where the Company’s US properties are located. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. In addition, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain, and additional seasonal weather variations will also affect access to these areas. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity during certain parts of the year.

The petroleum industry is highly competitive, and increased competitive pressures could adversely affect our business, financial condition, results of operations and prospects.

The petroleum industry is competitive in all of its phases. We compete with numerous other organizations in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas. Our competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than us. Our ability to increase our reserves in the future will depend not only upon our ability to explore and develop our present properties, but also upon our ability to select and acquire other suitable producing properties or prospects for exploratory drilling.

11

Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery and storage.

We do not control all of the assets that are used in the operation of our business and, therefore, cannot ensure that those assets will be operated in a manner favorable to us.

Other companies operate some of the assets in which we have an interest. As a result, we have a limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect our financial performance. Our return on assets operated by others will therefore depend upon a number of factors that may be outside of our control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.

Our ability to market oil and natural gas depends on our ability to transport our product to market. If we are unable to expand and develop the infrastructure in the areas surrounding certain of our assets, we may not be able to effectively market the oil and natural gas that we produce.

Due to the location of some of our assets, both in Canada and the United States, there is minimal infrastructure currently available to transport oil and natural gas from our existing and future wells to market. As a result, even if we are able to engage in successful exploration and production activities, we may not be able to effectively market the oil and natural gas that we produce, which could adversely affect our business, financial condition, results of operations and prospects.

Demand and competition for drilling equipment could delay our exploration and production activities, which could adversely affect our business, financial condition, results of operations and prospects.

13

Oil and natural gas exploration and development activities depend upon the availability of drilling and related equipment (typically leased from third parties) in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. To the extent we are not the operator of our oil and natural gas properties, we depend upon the operators of the properties for the timing of activities related to the properties and are largely unable to direct or control the activities of the operators.

Title to our oil and natural gas producing properties cannot be guaranteed and may be subject to prior recorded or unrecorded agreements, transfers, claims or other defects.

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, those reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat our claim. Unregistered agreements or transfers, or native land claims, may affect title. If title is disputed, we will need to defend our ownership through the courts, which would likely be an expensive and protracted process and have a negative effect on our operations and financial condition. In the event of an adverse judgment, we would lose our property rights. A defect in our title to any of our properties may have a material adverse effect on our business, financial condition, results of operations and prospects.

We may be unable to meet all of the obligations necessary to successfully maintain each of the licenses and leases and working interests in licenses and leases related to our properties, which could adversely affect our business, financial condition, results of operations and prospects.

Our properties are held in the form of licenses and leases and working interests in licenses and leases. If we or the holder of the license or lease fails to meet the specific requirement of a license or lease, the license or lease may terminate or expire. None of the obligations required to maintain each license or lease may be met. The termination or expiration of our licenses or leases or the working interests relating to a license or lease may have a material adverse effect on our business, financial condition, results of operations and prospects.

Risks related to financing continuing and future operations

We have a working capital deficiency and will be required to raise capital through financings. We may not be able to obtain capital or financing on satisfactory terms, or at all.

12

As of December 31, 2013,2015, the Company had a working capital deficiency of approximately $8.9$10.3 million. Excluding the non-cash warrant liability of $0.3 million related to the fair value of US$ denominated warrants issued in current and previous equity financings, the non-cash derivative liability of $0.3$1.2 million, related to the fair value of warrants issued in the loan facility which closed in June 2013 and the non-current portion ofadjusted working capital deficiency is approximately $9.1 million. Of this amount, $7.2 million is represented by a financial contract liability of $1.2 million,Dejour USA, which is due on September 30, 2016. The maximum cash component due in full settlement of the working capital deficiency mainly consistsfinancial contract liability is US$3.0 million. The remaining liability will likely be repaid through an assignment of a $2.9 million outstanding demand line of credit (maximum amount of line - $3.5 million)non-producing US oil and $2.9 million attributable to the outstanding loan facility.gas properties. We expect to incur general and administration expenses of approximately $3.0$2.0 million over the next twelve months. Our loan facility in the combined amount of $3.5 million is due and payable on December 22, 2014. Wemonths.We cannot assure you that debt or equity financing will be available to us, and even if debt or equity financing is available, it may not be on terms acceptable to us. Our inability to access sufficient capital for our operations would have a material adverse effect on our business, financial condition, results of operations and prospects.

The Company's ability to continue as a going concern is dependent upon attaining profitable operations and obtaining sufficient financing to meet obligations and continue exploration and development activities. Whether and when the Company can attain profitability is uncertain. These uncertainties cast substantial doubt upon the Company’s ability to continue as going concern.

During the year ended December 31, 2013,2015, the Company incurred a loss of $2.6$7.1 million and has an accumulated deficit of $90.8$105.2 million. Whether and when the Company can attain profitability is uncertain. The Company also has a working capital deficiency of $8.9$10.3 million as at December 31, 2013.2015. These uncertainties cast substantial doubt upon the Company’s ability to continue as going concern in the next twelve months, because we will be required to obtain additional capital in the future to continue our operations and there is no assurance that we will be able to obtain such capital, through equity or debt financing, or any combination thereof, or on satisfactory terms or at all. Our independent auditors have included an explanatory paragraph in their report on our consolidated financial statements for the year ended December 31, 20132015 that describes uncertainties that cast substantial doubt about our ability to continue as a going concern. Our audited consolidated financial statements have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board applicable to a going concern, which implies we will continue to meet our obligations and continue our operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and our consolidated financial statements do not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of the going concern uncertainty.

14

On November 21, 2013, the Company was advised by NYSE Regulation representing NYSE MKT LLC (“NYSE MKT” or “the Exchange”) that a review of the Company’s Form 6K for the period ended September 30, 2013 indicates the Company is not in compliance with three of the Exchange’s continued listing standards relating to minimum stockholders’ equity thresholds, consecutive annual net losses, and general “going concern” issues.

The Company has followed the procedures required by the Exchange to resolve these issues and, on April 17, 2014, NYSE Regulation reported that, in accordance with the NYSE’s Company Guide, the Company has made a reasonable demonstration of its ability to regain compliance with the Exchange’s “going concern” issues. The Company has committed to update NYSE Regulation as to its’ financial progress as appropriate or upon request but no later than at the completion of each quarter until full compliance is achieved on or before May 22, 2015, the target date for full compliance established by the Exchange.

On June 1, 2015, the Company received notification from the Exchange that it has regained compliance with the Exchange’s requirement addressing a company’s ability to continue to operate as a going concern.

On January 19, 2016, the Company received a letter from the Exchange stating that it is not in compliance with the continued listing standards as it pertains to the low price of its securities. In order to maintain its listing, the Company must address how it intends to regain compliance by July 19, 2016. If the plan is accepted, the Company may be able to continue its listing but will be subject to periodic reviews by the Exchange. If the plan is not accepted or if it is accepted but the Company is not in compliance with the continued listing standards by July 19, 2016, or if the Company does not make progress consistent with the plan, the Exchange may initiate delisting procedures as appropriate. The Company's management is pursuing options to eliminate any perceived deficiency, intends to submit a compliance plan on or before the deadline set by the Exchange.

We anticipate making substantial capital expenditures for future acquisition, exploration, development and production projects. We may not be able to obtain capital or financing necessary to support these projects on satisfactory terms, or at all.

We anticipate making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. If our revenues or reserves decline, we may not have access to the capital necessary to undertake or complete future drilling programs. Debt or equity financing, or cash generated by operations, may not be available to us or may not be sufficient to meet our requirements for capital expenditures or other corporate purposes. Even if debt or equity financing is available, it may not be on terms acceptable to us. Our inability to access sufficient capital for our operations could have a material adverse effect on our business, financial condition, results of operations and prospects.

13

Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times, thereby causing us to forfeit our interest in certain properties, miss certain acquisition opportunities and reduce or terminate our operations.

Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times and we are currently utilizing our bank line of credit to fund our working capital deficit. From time to time, we may require additional financing in order to carry out our oil and gas acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause us to forfeit its interest in certain properties, not be able to take advantage of certain acquisition opportunities and reduce or terminate our level of operations. If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, our ability to expend the necessary capital to replace our reserves or to maintain our production will be impaired. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or, if available, on favorable terms.

Debt that we incur in the future may limit our ability to obtain financing and to pursue other business opportunities, which could adversely affect our business, financial condition, results of operations and prospects.

From time to time, we may enter into transactions to acquire assets or equity of other organizations. These transactions may be financed in whole or in part with debt, which may increase our debt levels above industry standards for oil and natural gas companies of a similar size. Depending upon future exploration and development plans, we may require additional equity and/or debt financing that may not be available or, if available, may not be available on acceptable terms. None of our organizational documents currently limit the amount of indebtedness that we may incur. The level of our indebtedness from time to time could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

We may be exposed to the credit risk of third parties through certain of our business arrangements. Non-payment or non-performance by any of these third parties could have an adverse effect on our financial condition and results of operations.

15

We may be exposed to third-party credit risk through our contractual arrangements with our current or future joint venture partners, marketers of our petroleum and natural gas production and other parties. In the event those entities fail to meet their contractual obligations to us, those failures could have a material adverse effect on our financial condition and results of operations. In addition, poor credit conditions in the industry and of joint venture partners may affect a joint venture partner's willingness to participate in our ongoing capital program, potentially delaying the program and the results of the program until we find a suitable alternative partner.

Risks related to maintaining reserves and acquiring new sources of oil and natural gas

Our success depends upon our ability to find, acquire, develop and commercially produce oil and natural gas, which depends upon factors outside of our control.

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Our long-term commercial success depends upon our ability to find, acquire, develop and commercially produce oil and natural gas. We have only recently commenced production of oil and natural gas. There is no assurance that our other properties or future properties will achieve commercial production. Without the continual addition of new reserves, our existing reserves and our production will decline over time as our reserves are exploited. A future increase in our reserves will depend not only upon our ability to explore and develop any properties we may have from time to time, but also upon our ability to select and acquire new suitable producing properties or prospects. No assurance can be given that we will be able to locate satisfactory properties for acquisition or participation. Moreover, if acquisitions or participations are identified, we may determine that current market conditions, the terms of any acquisition or participation arrangement, or pricing conditions, may make the acquisitions or participations uneconomical, and further commercial quantities of oil and natural gas may not be produced, discovered or acquired by us, any of which could have a material adverse effect on our business, financial condition, results of operations and prospects.

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Properties that we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

Our long-term commercial success depends upon our ability to find, acquire, develop and commercially produce oil and natural gas reserves. However, our review of acquired properties is inherently incomplete, as it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in the reserve estimates or the underlying assumptions may adversely affect the quantities and present value of our reserves.

There are numerous uncertainties inherent in estimating quantities of oil, natural gas reserves and the future cash flows attributed to the reserves. Our reserve and associated cash flow estimates are estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the associated future net cash flows are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. All estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from our estimates of them, and those variations could be material.

Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas are estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves, and those variations could be material.

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Our future oil and natural gas production may not result in revenue increases and may be adversely affected by operating conditions, production delays, drilling hazards and environmental damages.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

Risks related to management of the Company

We may experience difficulty managing our anticipated growth.

We may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls. Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to attract and retain qualified management and technical personnel to meet the needs of our anticipated growth. Our inability to deal with this growth could have a material adverse effect on our business, financial condition, results of operations and prospects.

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We depend upon key personnel and the absence of any of these individuals could result in us having to cease operations.

Our ability to continue our operation business depends, in large part, upon our ability to attract and maintain qualified key management and technical personnel. Competition for such personnel is intense and we may not be able to attract and retain such personnel.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to successfully acquire additional licenses, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements depends on developing and maintaining close working relationships with industry participants and government officials and on our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

We cannot be certain that current expected expenditures and any current or planned completion/testing programs will be realized.

We believe that the costs used to prepare internal budgets are reasonable, however, there are assumptions, uncertainties, and risk that may cause our allocated funds on a per well basis to change as a result of having to alter certain activities from those originally proposed or programmed to reduce and mitigate uncertainties and risks. These assumptions, uncertainties, and risks are inherent in the completion and testing of wells and can include but are not limited to: pipe failure, casing collapse, unusual or unexpected formation pressure, environmental hazards, and other operating or production risk intrinsic in oil and or gas activities. Any of the above may cause a delay in any of our completion/testing programs or our ability to determine reserve potential.

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Risks related to federal, state, local and other laws, controls and regulations

We are subject to complex federal, provincial, state, local and other laws, controls and regulations that could adversely affect the cost, manner and feasibility of conducting our oil and natural gas operations.

Oil and natural gas exploration, production, marketing and transportation activities are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time. Governments may regulate or intervene with respect to price, taxes, royalties and the exportation of oil and natural gas. Regulations may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for crude oil and natural gas and increase our costs, any of which may have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, in order to conduct oil and natural gas operations, we require licenses from various governmental authorities. We cannot assure you that we will be able to obtain all of the licenses and permits that may be required to conduct operations that we may desire to undertake.

There is uncertainty regarding claims of title and rights of the aboriginal people to properties in certain portions of western Canada, and such a claim, if made in respect of our property or assets, could adversely affect our business, financial condition, results of operations and prospects.

Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada. We are not aware that any claims have been made in respect of its property and assets. However, if a claim arose and was successful it would have an adverse effect on our business, financial condition, results of operations and prospects.

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We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities, which could adversely affect our business, financial condition, results of operations and prospects.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation under a variety of federal, provincial, state and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with legislation can require significant expenditures, and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy any discharge. Environmental laws may result in a curtailment of production or a material increase in the costs of production, development or exploration activities, or otherwise adversely affect our business, financial condition, results of operations and prospects.

As a public company, our compliance costs and risks have increased in recent years.

Legal, accounting and other expenses associated with public company reporting requirements have increased significantly in the past few years. We anticipate that general and administrative costs associated with regulatory compliance will continue to increase with on-going compliance requirements under the Sarbanes-Oxley Act of 2002, as well as any new rules implemented by the SEC, Canadian Securities Administrators, the NYSE Amex Equities and the Toronto Stock Exchange in the future. These rules and regulations have significantly increased our legal and financial compliance costs and made some activities more time-consuming and costly. We cannot assure you that we will continue to effectively meet all of the requirements of these regulations, including Section 404 of the Sarbanes-Oxley Act and National Instrument 52-109 of the Canadian Securities Administrators. Any failure to effectively implement internal controls, or to resolve difficulties encountered in their implementation, could harm our operating results, cause us to fail to meet reporting obligations, or result in our principal executive officer and principal financial officer being required to give a qualified assessment of our internal control over financial reporting. Any such result could cause investors to lose confidence in our reported financial information, which could have a material adverse effect on the trading price of our common shares and our ability to raise capital. These rules and regulations have made it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage in the future. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.

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Risks Related to Our Being a Foreign Private Issuer

As a foreign private issuer, our shareholders may receive less complete and timely data.

We are a “foreign private issuer” as defined in Rule 3b-4 under the United States Securities Exchange Act of 1934. Our equity securities are accordingly exempt from Sections 14(a), 14(b), 14(c), 14(f) and 16 of the Exchange Act, pursuant to Rule 3a12-3 of the Exchange Act. Therefore, we are not required to file a Schedule 14A proxy statement in relation to our annual meetings of shareholders. The submission of proxy and annual meeting of shareholder information on Form 6-K may result in shareholders having less complete and timely information in connection with shareholder actions. The exemption from Section 16 rules regarding reports of beneficial ownership and purchases and sales of common shares by insiders and restrictions on insider trading in our securities may result in shareholders having less data and there being fewer restrictions on insiders’ activities in our securities.

It may be difficult to enforce judgments or bring actions outside the United States against us and certain of our directors and officers.

It may be difficult to bring and enforce suits against us. We are incorporated in British Columbia, Canada. Many of our directors and officers are not residents of the United States and some of our assets are located outside of the United States. As a result, it may be difficult for U.S. holders of our common shares to effect service of process on these persons within the United States or to enforce judgments obtained in the U.S. based on the civil liability provisions of the U.S. federal securities laws against us or our officers and directors. In addition, a shareholder should not assume that the courts of Canada (i) would enforce judgments of U.S. courts obtained in actions against us or our officers or directors predicated upon the civil liability provisions of the U.S. federal securities laws or other laws of the United States, or (ii) would enforce, in original actions, liabilities against us or our officers or directors predicated upon the U.S. federal securities laws or other laws of the United States.

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Risks related to investing in our common shares

We have not paid any dividends on our common shares. Consequently, your only opportunity currently to achieve a return on your investment will be if the market price of our common shares appreciates above the price that you pay for our common shares.

We have not declared or paid any dividends on our common shares since our incorporation. Any decision to pay dividends on our common shares will be made by our board of directors on the basis of our earnings, financial requirements and other conditions existing at such future time. Consequently, your only opportunity to achieve a return on your investment in our securities will be if the market price of our common shares appreciates and you are able to sell your common shares at a profit.

Our common share price has been volatile and your investment in our common shares could suffer a decline in value.

Our common shares are traded on the Toronto Stock Exchange and the NYSE Amex Equities.MKT. The market price of our common shares may fluctuate significantly in response to a number of factors, some of which are beyond our control. These factors include price fluctuations of precious metals, government regulations, disputes regarding mining claims, broad stock market fluctuations and economic conditions in the United States.

Dilution through officer, director, employee, consultant or agent options could adversely affect our shareholders.

Because our success is highly dependent upon our officers, directors, employees, consultants and agents, we have granted to some or all of our key officers, directors, employees, consultants and agents options to purchase common shares as non-cash incentives. To the extent that we grant significant numbers of options and those options are exercised, the interests of our other shareholders may be diluted.

The issuance of additional common shares may negatively affect the trading price of our common shares.

We have issued equity securities in the past and may continue to issue equity securities to finance our activities in the future, including to finance future acquisitions, or as consideration for acquisitions of businesses or assets. In addition, outstanding options and warrants to purchase our common shares may be exercised, resulting in the issuance of additional common shares. The issuance by us of additional common shares would result in dilution to our shareholders, and even the perception that such an issuance may occur could have a negative effect on the trading price of our common shares.

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Introduction

Our executive office is located at:

at Suite 598, – 999 Canada Place,
Vancouver, British Columbia, Canada V6C 3E1
Telephone:3E1; telephone: (604) 638-5050
Facsimile: and facsimile: (604) 638-5051
Website:www.dejour.com
Email:rhodgkinson@dejour.comordmatheson@dejour.com

638-5051. The contact person is: Mr. Robert L. Hodgkinson, Co-Chairman and Chief Executive Officer (email:rhodgkinson@dxienergy.com) or Mr. David Matheson, Chief Financial Officer.Officer (email:dmatheson@dxienergy.com).

Our common shares tradeare traded on the Toronto Stock Exchange and the NYSE Amex EquitiesNew York Stock Exchange under the symbol “DEJ”“DXI”.

Our authorized capital consists of three classes of shares: an unlimited number of common voting shares; an unlimited number of preferred shares designated as First Preferred Shares, issuable in series; and an unlimited number of preferred shares designated as Second Preferred Shares, issuable in series. There are no indentures or agreements limiting the payment of dividends and there are no conversion rights, special liquidation rights, pre-emptive rights or subscription rights.

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The First Preferred Shares have priority over the Common Shares and the Second Preferred Shares with respect to the payment of dividends and in the distribution of assets in the event of a winding up of Dejour.DXI Energy. The Second Preferred Shares have priority over the Common Shares with respect to dividends and surplus assets in the event of a winding up of Dejour.DXI Energy.

As of December 31, 2013,2015, there were 148,916,37436,509,953 common shares issued and outstanding. As of December 31, 2013,2015, there were no First Preferred Shares and no Second Preferred Shares issued and outstanding.

Incorporation and Name Changes

DejourDXI Energy Inc. (formerly Dejour Enterprises Ltd.Energy Inc.) is incorporated under the laws of British Columbia, Canada. The Company was originally incorporated as “Dejour Mines Limited” on March 29, 1968 under the laws of the Province of Ontario. By articles of amendment dated October 30, 2001, the issued shares were consolidated on the basis of one (1) new for every fifteen (15) old shares and the name of the Company was changed to Dejour Enterprises Ltd. On June 6, 2003, the shareholders approved a resolution to complete a one-for-three-share consolidation, which became effective on October 1, 2003. In 2005, the Company was continued in British Columbia under theBusiness Corporations Act(British Columbia). On March 9, 2011, the Company changed its name from Dejour Enterprises Ltd. to Dejour Energy Inc.

On June 29, 2015, the Company’s shareholders approved the consolidation of its issued and outstanding common shares on the basis of one (1) post-consolidation common share for every five (5) pre-consolidation common shares. On October 27, 2015, the Company changed its name from Dejour Energy Inc. to DXI Energy Inc. and effected a five-to-one share consolidation of its common shares. The Company began trading on a post-consolidation basis on October 30, 2015.

Financings

We have financed our operations through funds from loans, public/private placements of common shares, common shares issued for property, common shares issued in debt settlements, and shares issued upon exercise of stock options and share purchase warrants. The following table summarizes our financings for the past three fiscal years.

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Past Capital Expenditures

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Capital Expenditures

DejourDXI Energy is committed to future growth through its strategy to implement a full-cycle exploration and development program, augmented by strategic acquisitions with exploitation upside.

During the year ended December 31, 2015, the Company incurred $1.0 million to complete and tie into production the 2 infill wells that were recently drilled at its Woodrush properties, north of Fort St. John, British Columbia. In the U.S., the Company paid $4.5 million for the ongoing Kokopelli development program in Colorado and it is related to the drilling, casing and completion of eight natural gas wells.

During the year ended December 31, 2014, the Company acquired certain natural gas producing assets and related processing facilities adjacent to its existing Woodrush oilfield at Ft. St. John, British Columbia, resulting in the acquisition of an additional 9,600 net acres (44% developed). Additionally, the Company acquired an additional 24% working interest in its existing Woodrush oilfield to increase the working interest to 99%.

During the year ended December 31, 2013, the Company drilled three new wells to the Williams Fork formation at Kokopelli, the Company’s core operating area in the Piceance Basin of Colorado. The Company also completed these wells and one other previously drilled well. The operations were primarily funded by a U.S. based drilling fund.

During the year ended December 31, 2012, the Company incurred $2.2 million on drilling and completion operations. Equipment and facility expenditures were $1.4 million. The balance of $0.8 million was mostly related to the capitalization of general and administrative costs and lease rentals on its oil and gas interests.

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Additions to property and equipment and exploration and evaluation assets:

(1) excludes non-cash capital expenditures of $443,000 (US$417,000)$1,520,000 related to joint venture financing (see ‘Financial Contract Liability’ sectionthe acquisition of the MD&A for details)certain property and equipment in March 2014

Daily Production

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The decreaseincrease in oil production for Q4 2013 was mainly the result ofyear ended December 31, 2015 is related to the temporary curtailmentcommencement of production associated with routine repairs and maintenance at one offrom the mainnew oil producing well at Woodrush.Woodrush in January 2015, combined with the added production from enhancements to the waterflood operation.

The increase in natural gas production for the current year was attributableended December 31, 2015 is related to the commencement of production from the fournew gas well at Woodrush in January 2015 and the eight new wells at Kokopelli in September 2015. This was offset by the disposition of 65% of the Company’s working interest in its core natural gas property in the eastern portion of Piceance Basin of Colorado on June 30, 2014 and the “turnaround” of the McMahon gas plant near Ft. St. John, British Columbia in August 2013.June 2015 for approximately 40 days.

General

The Company is in the business of acquiring, exploring and developing energy projects with a focus on oil and gas exploration in Canada and the United States.

The Company holds approximately 79,00053,800 net acres of oil and gas leases in the following regions:

Summary

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Over the past few years, the Company has continued to develop its Halfway oilfield in northeastern British Columbia, Canada while evaluating its exploration prospects in the Piceance Basin with the intent of developing drillable prospects of merit at the earliest possible opportunity. This process involved several distinct steps:

As a result of this process, the Company’s assets in Canada and the Piceance basin have moved to a higher weighting of lower risk development projects as opposed to higher risk exploration projects.

Our business objective is to grow our oil and gas production and generate sufficient cash flow to continue to expand company operations and enhance shareholder value.

Specialized Skill and Knowledge:Exploration for and development of petroleum and natural gas resources requires specialized skills and knowledge including in the areas of petroleum engineering, geophysics, geology and title. The Company and its subsidiaries have obtained personnel with the required specialized skills and knowledge to carry out their respective operations. While the current labour market in the industry is highly competitive, the Company expects to be able to attract and maintain appropriately qualified employees for fiscal 2014.2016.

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Cycles:All of the Company's operations in Canada are affected by seasonal operating conditions. Dejour Energy (Alberta) Ltd. holds properties in northwestern Alberta and northeastern British Columbia which are accessible to heavy equipment in winter only when the ground is frozen, typically between December to early April. For this reason drilling and pipeline construction ceases over the remainder of the year, limiting growth to winter only. Production operations continue year round in these areas once production is established. The prices that the Company will receive for oil and gas production in the future are weighted to world benchmark prices and may be adversely affected by mild weather conditions. Following a significant increase in oil prices in 2007 and the initial half of 2008, oil prices have been relatively stable in the US$85.00 to US$100.00 range for the past 5 years.years of 2008 to 2013. Oil prices declined by more than 70% to a 12-year low since June 2014 under pressure from a global glut of crude oil. In early December 2013, extreme cold weather from the polar vortex has resulted in a sharp increase of about 25% to 30% in the price paid to producers for their production of natural gas. It is expected that2015, natural gas prices will remainwere relatively firm at this higher levellow for most of 2014 as US storage facilities are replenished following emergency withdrawalsthe year because of natural gas to meet coldexcess supply and mild weather demands.forecast.

Commodity price cycles are also affected by world industrial supply and demand, domestic and international commodity transportation systems, and political factors affecting construction of pipelines and exports of controversial commodities like liquid natural gas. See"Risk Factors – Risks related to operating an exploration, development and production company".

Environmental Protection:The Company's operations are subject to environmental regulations (including regular environmental impact assessments and permitting) in the jurisdictions in which it operates. Such regulations cover a wide variety of matters, including, without limitation, emission of greenhouse gases, prevention of waste, pollution and protection of the environment, labour regulations and worker safety. Under such regulations there are preventative obligations, clean-up costs and liabilities for toxic or hazardous substances which may exist on or under any of its properties or which may be produced as a result of its operations. Environmental legislation and legislation relating to exploration and production of oil and natural gas will require stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental assessments of proposed projects and a heightened degree of responsibility for companies and their directors and employees. Such stricter standards could impact the Company's costs and have an adverse effect on results of operations. The Company expects to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed; however, the Company does not anticipate making material expenditures beyond normal compliance with environmental regulations in 20142016 and future years.

Employees:The Company had the equivalent of approximately 10 full-time employees and consultants during 2013.2015.

Social or Environmental Policies:The health and safety of employees, contractors and the public, as well as the protection of the environment, is of utmost importance to the Company. The Company endeavors to conduct its operations in a manner that will minimize adverse effects of emergency situations by:

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The Company believes that all Company personnel have a vital role in achieving excellence in environmental, health and safety performance. This is best achieved through careful planning and the support and active participation of everyone involved.

Competitive Conditions: The Company operates in geographical areas where there is strong competition by other companies for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel. The Company’s competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators, many of whom have greater financial and personnel resources than the Company. The Company’s ability to acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers is dependent upon developing and maintaining close working relationships with its current industry partners and joint operators, and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.

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Three Year History

2015

During the year ended December 31, 2015, the Company:

2014

During the year ended December 31, 2014, the Company:

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2013

During the year, the Company continued oil and gas production operations at the Drake/Woodrush oilfield near Ft. St. John, British Columbia, and commenced drilling operations at Kokopelli in the Piceance Basin of Colorado.

The Company achieved the following operational and financial objectives:

2012

In 2012, the Company continued its focus on production optimization of the Drake/Woodrush oilfield in northeastern British Columbia, Canada, while preparing for drilling and production activities in the Piceance Basin.

During the year, the Company achieved the following objectives:

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2011

In 2011, the Company optimized production at the Drake/Woodrush property, and completed pre-drilling and lease curing activities at Kokopelli. The Company also drilled a successful discovery well at South Rangely.

Key achievements were:

United States vs. Foreign Sales/Assets

Commodity Price Environment

Generally, the demand for, and the price of, natural gas increases during the colder winter months and decreases during the warmer summer months. Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Crude oil and the demand for heating oil are also impacted by seasonal factors, with generally higher prices in the winter. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations.

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Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The market for oil and natural gas is beyond our control and prices are difficult to predict. (See also ‘Trend Information’ under item 5 ‘Operating and Financial Review and Prospects’)

Forward Contracts

The Company is not bound by an agreement (including any transportation agreement) directly or through an aggregator, under which it may be precluded from fully realizing, or may be protected from the full effect of, future market prices for oil and gas. The Company had no commodity contracts in place at December 31, 2013.2015.

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Additional Information Concerning Abandonment and Reclamation Costs

For the Company’s Canadian and US oil and gas interests, the well abandonment costs for all wells with reserves have been included at the property level. The Company estimated the total undiscounted amount of the cash flows required to settle the decommissioning liabilities as at December 31, 20132015 to be approximately $1,856,000.$4,440,000. These obligations are expected to be settled over the next 15 years with the majority of costs incurred between 2016 and 2028. Additional abandonment costs associated with non-reserves wells, lease reclamation costs and facility abandonment and reclamation expenses have not been included.2030.

Government Regulations

Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive laws and regulations promulgated by federal, state, tribal and local authorities and agencies. These laws and regulations often require permits for drilling operations, drilling bonds and reports concerning operations, and impose other requirements relating to the exploration for and production of oil and natural gas. Many of the laws and regulations govern the location of wells, the method of drilling and casing wells, the plugging and abandoning of wells, the restoration of properties upon which wells are drilled, temporary storage tank operations, air emissions from flaring, compression, the construction and use of access roads, sour gas management and the disposal of fluids used in connection with operations.

Our operations are subject to environmental regulations (including regular environmental impact assessments and permitting) in the jurisdictions in which it operates. Such regulations cover a wide variety of matters, including, without limitation, emission of greenhouse gases, prevention of waste, pollution and protection of the environment, labour regulations and worker safety. Under such regulations there are preventative obligations, clean-up costs and liabilities for toxic or hazardous substances which may exist on or under any of its properties or which may be produced as a result of its operations. Environmental legislation and legislation relating to exploration and production of oil and natural gas will require stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental assessments of proposed projects and a heightened degree of responsibility for companies and their directors and employees. Such stricter standards could impact our costs and have an adverse effect on results of operations.

The Comprehensive Environmental, Response, Compensation, and Liability Act, or CERCLA, and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. It is not uncommon for the government to file claims requiring cleanup actions, demands for reimbursement for government-incurred cleanup costs, or natural resource damages, or for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize the imposition of substantial fines and penalties for noncompliance, as well as requirements for corrective actions. Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum-related products. In addition, although RCRA classifies certain oil field wastes as "non-hazardous," such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. CERCLA, RCRA and comparable state statutes can impose liability for clean-up of sites and disposal of substances found on drilling and production sites long after operations on such sites have been completed. Other statutes relating to the storage and handling of pollutants include the Oil Pollution Act of 1990, or OPA, which requires certain owners and operators of facilities that store or otherwise handle oil to prepare and implement spill response plans relating to the potential discharge of oil into surface waters. The OPA, contains numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States. State laws mandate oil cleanup programs with respect to contaminated soil. A failure to comply with OPA's requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions.

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The Endangered Species Act, or ESA, seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, or destroy or modify the critical habitat of such species. Under the ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. The ESA has been used to prevent or delay drilling activities and provides for criminal penalties for willful violations of its provisions. Other statutes that provide protection to animal and plant species and that may apply to our operations include, without limitation, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act. Although we believe that our operations are in substantial compliance with these statutes, any change in these statutes or any reclassification of a species as threatened or endangered or re-determination of the extent of "critical habit" could subject us to significant expenses to modify our operations or could force us to discontinue some operations altogether.

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The National Environmental Policy Act, or NEPA, requires a thorough review of the environmental impacts of "major federal actions" and a determination of whether proposed actions on federal and certain Indian lands would result in "significant impact." For purposes of NEPA, "major federal action" can be something as basic as issuance of a required permit. For oil and gas operations on federal and certain Indian lands or requiring federal permits, NEPA review can increase the time for obtaining approval and impose additional regulatory burdens on the natural gas and oil industry, thereby increasing our costs of doing business and our profitability.

The Clean Water Act, or CWA, and comparable state statutes, impose restrictions and controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the Environmental Protection Agency (EPA) or an analogous state agency. The CWA regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.

The Safe Drinking Water Act, or SDWA,Hydraulic fracturing is an important and the Underground Injection Control (UIC) program promulgated thereunder, regulate the drilling and operationcommon practice that is used to stimulate production of subsurface injection wells. EPA directly administers the UIC program in some states and in others the responsibility for the program has been delegated to the state. The program requires that a permit be obtained before drilling a disposal well. Violation of these regulationsoil and/or contaminationnatural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of groundwaterwater, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing as part of our operations. The process is typically regulated by state oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities undercommissions but the SWDA and state laws.EPA has asserted federal regulatory authority pursuant to the Safe Water Drinking Act, or SDWA, over certain hydraulic fracturing activities involving the use of diesel. In addition, third party claims mayin May, 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substance Control Act. To date, no other action has been taken. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting disclosure, and well construction requirements on hydraulic fracturing activities.

We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate (primarily the State of Colorado at present), we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.precluded from drilling wells.

The Clean Air Act, as amended, restricts the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to remain in compliance. In addition, the EPA has promulgated more stringent regulations governing emissions of toxic air pollutants from sources in the oil and gas industry, and these regulations may increase the costs of compliance for some facilities.

Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production. Many state governments have enacted legislation directed at controlling greenhouse gas emissions, and future state and federal legislation and regulation could impose additional restrictions or requirements in connection with our operations and favor use of alternative energy sources, which could increase operating costs and demand for oil products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.

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We expect to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed; however, we do not anticipate making material expenditures beyond normal compliance with environmental regulations in 20142016 and future years.

The health and safety of employees, contractors and the public, as well as the protection of the environment, is of utmost importance to us. We endeavour to conduct our operations in a manner that will minimize adverse effects of emergency situations by:

• complying with government regulations and standards;
• following industry codes, practices and guidelines;
• ensuring prompt, effective response and repair to emergency situations and environmental incidents; and
• educating employees and contractors of the importance of compliance with corporate safety and environmental rules and procedures.

We believe that all of our personnel have a vital role in achieving excellence in environmental, health and safety performance. This is best achieved through careful planning and the support and active participation of everyone involved.

Competition

We operate in geographical areas where there is strong competition by other companies for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel. Our competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators, many of whom have greater financial and personnel resources than us. Our ability to acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers is dependent upon developing and maintaining close working relationships with its current industry partners and joint operators, and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.

We compete with many companies possessing greater financial resources and technical facilities for the acquisition of oil and gas properties, exploration and production equipment, as well as for the recruitment and retention of qualified employees.

Seasonality

All of ourThe Company’s core operations are in Canada and they are affected by seasonal operating conditions. Dejour Energy (Alberta) Ltd., ourits wholly owned subsidiary, holds properties in northwestern Alberta and northeastern British Columbia which are accessible to heavy equipment in winter only when the ground is frozen, typically between December to early April. For this reason drilling and pipeline construction ceases over the remainder of the year, limiting growth to winter only. Production operations continue year round in these areas once production is established. The prices that we will receive for oil and gas production in the future are weighted to world benchmark prices and may be adversely affected by mild weather conditions.

We have four 100% ownedthree wholly-owned subsidiaries:

• Dejour Energy (USA) Corp. (“Dejour USA”), a Nevada corporation, holds Dejour's United States oil and gas interests,
• Dejour Energy (Alberta) Ltd. (“DEAL”), an Alberta corporation, holds its Canadian oil and gas interests in northwestern Alberta and northeastern British Columbia;
• Wild Horse Energy Ltd. (“Wild Horse”), an inactive Alberta corporation, and
• 0855524 B.C. Ltd. (“0855524”), a British Columbia Corporation, which is currently inactive.

D. Property, Plant and Equipment27

Our executive offices are located in rented premises of approximately 2,519 sq. ft. at Suite 598, – 999 Canada Place, Vancouver, British Columbia, V6C 3E1. We began occupying these facilities on July 1, 2009.

Resource Properties

Our current focus is on oil and gas properties located in the United States and Canada and currently have oil and gas leases in the following regions:

• The Piceance, Paradox and Uinta Basins in the US Rocky Mountains.
• The Peace River Arch of northeastern British Columbia and northwestern Alberta, Canada.

US Oil and Gas Interests

Kokopelli, Piceance Basin

During 2012, the Company drilled an initial well into the WillamsWilliams Fork natural gas formation at Kokopelli to hold its 2,200 gross acres (1,571 net)(550 net acres) of leasehold interests. The Company also entered into a financial contract with an industry Drilling Fund to complete and tie-in the initial well and drill, complete, and tie-in an additional 3 wells. The Drilling Fund’s investment of US$7,000,000 (an initial investment of US$6,500,000 supplemented with an additional US$500,000 for a total of US$7,000,000) represents about 67% of the total program cost of US$10,400,000. The primary producing geological horizons are the Williams Fork and Niobrara/Mancos zones at depths ranging from 9,000 to 10,500 ft. respectively.

The Company’s 4-well drillingDuring 2013, the Company drilled three additional wells and completion programcompleted all four wells in the Williams Fork formation. Production commenced in September, 2013.

On June 30, 2014, the Company sold 65% of its 71.43% working interest in the 4 wells, together with 65% of its remaining 1,542 acres at Kokopelli focused strictly onfor US$4,000,000 cash and a commitment by the Purchaser to spend US$16,000,000 at Kokopelli to drill, complete, and equip seven wells to the base of the Williams Fork formation and one well to the base of the Mancos/Niobrara formation. Pursuant to the terms of the Purchase and Sale Agreement, the Company was “carried” for 25% through the entire expenditure of US$16,000,000.

During 2015, the Company completed the drilling, casing and completion of eight natural gas wells in September, 2013.

Dejourthe Kokopelli development project in Colorado. Production from the eight natural gas wells commenced in the 4^th quarter of 2015. The Company has a 72%25% working interest in 139 proved undeveloped locations at the Kokopellithis project. To date, the Company has delineated all proved undeveloped (“PUD”) drilling locations on 10-acre spacing in the Williams Fork. As at December 31, 2013, the total proved reserves, net to the Company’s working interest, are 18.6 million BOE having an NPV before tax, discounted at 10% of $90 million. WPX Energy, Rocky Mountain LLC, Inc. and Bill Barrett Corporation are developing and producing the Williams Fork on adjacent acreage to the east, west and north of the Company’s acreage. Dejour has worked closely with important constituents including local citizenry and the Bureau of Land Management (“BLM”) in the US and the Colorado Division of Wildlife (“Dept. of Wildlife”) to develop a mutually acceptable development plan for this environmentally sensitive area.

The Company will baseand its future development plans forpartners intend to continue to develop the Kokopelli for 2014 and 2015 on an assessment of (a) the NYMEX futures market forProject when natural gas (b) theand natural gas liquids markets at the Mt. Belvieu, Texas and Conway, Kansas sales points, and (c) the abilityprices paid to secure a joint venture financing arrangement with a partner capable of financing upproducers return to a 75% working interest in a 30-well Williams Fork development (“Phase 1”) followed closely by a minimum of 20 wells in a Phase 2 program.acceptable levels.

Roan Creek, Piceance Basin

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On November 5, 2012,During 2014, the Company entered intocommissioned a “Lease Purchase“Prospective Reserve Report”, by Gustavson and Farmout Agreement” (“Associates, on the Agreement”) with a US explorationCompany’s 1,960-acre lease at Roan Creek.

The Report concluded there are 70 Bcf of “contingent” natural gas resources and production (“E&P”) company with respect51 Bcf of “prospective” natural gas reserves to itsbe developed at Roan Creek acreage. Approximately 2,300 acres were sold for cash while the remaining 5,200 acres were included in a Farmout Agreement (“the Agreement”) with the following terms and conditions:

During the third quarter of 2013, the Company was informed by the E&P company that it would not drill the test wells and, per the Agreement, would pay the Company a US$275,000 cash penalty on or before June 30, 2014. The penalty payment addresses the relinquishment of 3,240 of the 5,200 acres covered by the Agreement back to the Bureau of Land Management.Creek.

The Company is seeking joint venture partnerswill continue to further explore the remaining Roan Creek acreage of 1,960 acres.when commodity prices recover to acceptable levels.

Canadian Oil and Gas Interests

Drake/Woodrush, Ft.Fort St. John, British Columbia

The Company’s Drake/Woodrush oilfield is located about 110 km. north of Ft.Fort St. John, British Columbia, Canada. During 2013,In December 2014, the Company produced approximately 75,000 BOE and 249,000 MMcf of natural gas from the 3 oil wells and 5 natural gas wells producing from the Halfway geological formation.

The Company owns a 75% working interest in the Drake/Woodrush oilfield and is the contractual “Operator” of the wells and related production facilities and pipelines.

The Drake/Woodrush oilfield production is being enhanced by a system of waterflood pressure maintenance which currently injects approximately 2,400 BOWD into the formation to maintain reservoir pressure. The Company re-cycles the produced water and re-injects the water volumes back into the reservoir.

The Company plans to further develop the natural gas potential of the Drake/Woodrush oilfield via recompletions of existing wells andcommenced the drilling of at least one new well. This program is dependent upon continued stronger prices for2 infill wells (1 oil well and 1 natural gas well) in the Peace Arch area of northeasternNortheastern, British Columbia. In January 2015, the Company successfully completed the 2 wells and tied them into production.

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Summary of Operational Highlights

For the year ended December 31, 2013 (“fiscal 2013”), total revenue, before royalties, increased by $2,435,000 or, 35%, was due to a 35% increase in oil and gas production over the year ended December 31, 2012 (“fiscal 2012”).

The increase in natural gas production for the current year was attributable to the commencement of production from the four new wells at Kokopelli in the eastern portion of Piceance Basin of Colorado in August 2013.

Oil Operations

The average price received for oil sales in fiscal 2013 increased in line with the Edmonton Par oil prices which averaged $93.24 per barrel in fiscal 2013, compared to $86.53 per barrel received in fiscal 2012.

Average oil royalties paid for the year ended December 31, 2013 were consistent with those paid in the year ended December 31, 2012.

Operating and transportation expenses averaged $26.75 per barrel in fiscal 2013. This represents a decrease of 29% from $37.57 per barrel in fiscal 2012. The decrease in per unit operating and transportation expenses in fiscal 2013 resulted from the non-recurring costs of major workovers on one of the oil producing wells at Woodrush in 2012 and the allocation of fixed operating costs over a higher oil production volume.

Natural Gas Operations

The average price received for gas sales increased by 58% for fiscal 2013, relative to the corresponding period of the prior year. The increase in Dejour’s average realized gas price for the current year reflected higher benchmark prices.

Average gas royalties for fiscal 2013 were higher compared to the corresponding period of the prior year. Initiation of gas production from the four new wells at Kokopelli contributed to the increase in royalties in both periods as the effective rate in Colorado is approximately 50% higher than the lower royalty rates for marginal gas production in British Columbia. Additionally, lower gas royalty rates in 2012 are a result of lower gas prices and gas cost allowance credits under the province of British Columbia royalty framework.

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Operating and transportation expenses averaged $2.06 per mcf in fiscal 2013. This represents a decrease of 24% from $2.72 per mcf in fiscal 2012. The decrease in per unit operating and transportation expenses is due to the increase in lower-cost Colorado gas production as a percent of the Company’s total gas production.

Reserve Data

The standards of the SEC require that proved reserves be estimated using existing economic conditions (constant pricing). Based on this methodology, the Company’s results have been calculated utilizing the 12-month average price for each of the years presented.

The Company reports in Canadian currency and therefore the Reserves Data set forth in the tables below has been converted to Canadian dollars at the prevailing conversion rate at December 31, 2013.2015. The conversion rate used per Bank of Canada is 1.0636.1.3840.

In 2013,2015, GLJ Petroleum Consultants (“GLJ”), independent petroleum engineering consultants based in Calgary, Alberta was retained by the Company to evaluate the Canadian properties of the Company. Their report, titled “Third Party Report on Reserves, Dejour Energy (Alberta) Ltd.”, is dated February 19, 201425, 2016 and has an effective date of December 31, 2013.2015.

Gustavson Associates (“Gustavson”), an independent petroleum engineering consultants based in Denver, Colorado were retained by the Company to evaluate the US properties of the Company. Their report, titled “Reserve Estimate and Financial Forecast as to Dejour’s Interests in the Kokopelli Field Area, Garfield County, Colorado” is dated March 14, 2014February 25, 2016 and has an effective date of January 1, 2014.2016.

The reserves data set forth below (the "Reserves Data"), derived from GLJ and Gustavson’s reports, summarizes our oil, liquids and natural gas reserves.

The GLJ and Gustavson reports are based on certain factual data supplied by the Company, and GLJ and Gustavson's opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to the Company’s petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Company to GLJ and Gustavson and accepted without any further investigation. GLJ and Gustavson accepted this data as presented and neither title searches nor field inspections were conducted. All statements relating to the activities of the Company for the year ended December 31, 20132015 include a full year of operating data on the properties of the Company.

The reserve estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas liquids and natural gas reserves may be greater than or less than the estimates provided herein.

Controls Over Reserve Report Preparation

Our reserve estimates reports as of December 31, 20132015 are prepared by our independent qualified reserve evaluators, GLJ and Gustavson. To ensure accuracy and completeness of the data prior to disclosure of reserve estimates to the public, our reserves committee does the following: (1) reviews our procedures for providing information to the independent qualified reserve evaluators, (2) meets with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the qualified reserves evaluators to report without reservation, (3) reviews the reserves data with management and the independent qualified reserves evaluator. If the reserve committee is satisfied with results of its evaluation it will approve the content of our reserve disclosure. If any concerns arise in the reserve committee’s evaluation, the reserve committee will work with our management and the independent qualified reserves evaluators to resolve the issues before disclosure of reserves is made public.

As of December 31, 2013,2015, the Company’s reserve committee was composed of: Craig Sturrock, Ross Gorrell and Ronnie Bozzer. Please see “Item 6. Directors, Senior Management and Employees, A. Directors and Senior Management” for biographical information on the members of the reserve committee.

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Summary of Oil and Gas Reserves as of Fiscal Year-End Based on Average Fiscal Year Prices

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Given acceptableeconomic commodity prices, 100% of the Company’s undevelopedCompany plans to fully develop its reserves are scheduled to be developed withinover the next fourfive years.

Canada – IncreaseDecrease in Total Proved Oil Reserves of 26 Mbbls and Natural Gas Reserves of 5511,009 MMcf:

During the year ended December 31, 2013, an expected increase2015, the reduction in light and medium oil reserves and natural gas reserves was primarily as there are more favorable decline curves and additional solution gas from the proved undeveloped location. GLJ increased, by waya result of a technical revision, the Company’s total provedsignificantly lower 12-month average trailing oil and natural gas reserves by 551 MMcf.prices.

United States – IncreaseDecrease in Total Proved Natural Gas Liquids Reserves of 1,7261,710 Mbbls and Natural Gas Reserves of 41,57128,841 MMcf:

During the year ended December 31, 2013, an expected increase2015, the reduction in the natural gas liquids reserves and natural gas liquids reserves was primarily as this resulted from a successful 2013 drilling program which converted 47 “probable” drilling locations at December 31, 2012 to “proven” as at December 31, 2013. Gustavson increased, by wayresult of an extension, the Company’s total proved natural gasa significantly lower 12-month average trailing oil and natural gas liquids by 41,571 MMcfprices, and 1,726 Mbbls, respectively.the loss of proved undeveloped reserves at Kokopelli due to the failure to meet economic criteria.

Total Proved Reserves

The table below compares our estimated proved reserves and associated present value (discounted at an annual rate of 10%) of the estimated future revenue before income tax.

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Reconciliation to Standardized Measure

Notes:

Oil and Gas Production, Production Prices and Production Costs

The following is our total net oil and gas production for the fiscal years ended December 31, 2013, 20122015, 2014 and 2011.2013. Production came from our Canadian and United States properties. Production from our United States properties commenced in the fiscal year ended December 31, 2013.

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The following table includes the average prices the Company received for its production for the fiscal years ended December 31, 2013, 20122015, 2014 and 2011.2013.

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The following table includes the average production cost, not including ad valorem and severance taxes, per unit of production for the fiscal years ended December 31, 2013, 20122015, 2014 and 2011.2013.

Drilling and Other Exploratory and Development Activities

During the fiscal year ended December 31, 2015, no wells were drilled in Canada and the United States.

During the fiscal year ended December 31, 2014, we drilled the following wells in Canada and the United States:

During the fiscal year ended December 31, 2013, no wells were drilled in Canada and we drilled the following wells in the United States:

During the fiscal year ended December 31, 2012, no wells were drilled in Canada and we drilled the following wells in the United States:

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During the fiscal year ended December 31, 2011, we drilled the following wells:

Delivery Commitments

We have no current delivery commitments for either oil or natural gas.

Oil and Gas Properties and Wells

AsThe following tables summarizes the number of producing and non-producing wells as at December 31, 2013, we had 11 gross (7.46 net) producing or shut-in oil or natural gas wells.2015:

As of December 31, 2012, we had 11 gross (7.33 net) producing or shut-in oil or natural gas wells.

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AsThe following tables summarizes the number of producing and non-producing wells as at December 31, 2011, we had 10 gross (7.13 net)2014:

The following tables summarizes the number of producing or shut-in oil or natural gas wells.and non-producing wells as at December 31, 2013:

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Interest in Oil and Gas Properties

The following table sets forth information for our interest in oil and gas properties as of December 31, 20132015 relating to our leasehold acreage. Developed acres are acres spaced or assigned to productive wells including undrilled acreage held-byproduction under the terms of a lease. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas or oil, regardless of whether such acreage contains proved reserves. Gross acres are the total number of acres in which a working interest is owned. Net acres are the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

As at December 31, 2013,2015, the Company’s developed and undeveloped acres are as follows:

The Company’s net undeveloped acres as of December 31, 2013,2015, together with expiries for the period from 20142016 to 20162018 and thereafter is as follows.

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ITEM 4A. UNRESOLVED STAFF COMMENTS

Not Applicable.

ITEM 5.    OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following is a discussion of our consolidated operating results and financial position, including all our wholly-owned subsidiaries. It should be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 20132015 and related notes included therein under the heading "Item 18. Financial Statements" below.

The financial statements of the Company for the years ended December 31, 2013, 20122015, 2014, and 20112013 are prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”).

Certain forward-looking statements are discussed in this Item 5 with respect to our activities and future financial results. These are subject to risks and uncertainties that may cause projected results or events to differ materially from actual results or events. Readers should also read the "Cautionary Note Regarding Forward-Looking Statements" above and “Item 3. Key Information - Risk Factors.”

CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS

The Company makespreparation of financial statements in accordance with IFRS requires management to make estimates and assumptions about the futurejudgments that affect the reported amounts of assets, liabilities, revenues, expenses, gains, and liabilities. Estimateslosses. These estimates and judgments are continually evaluatedsubject to change based on historical experience and other factors, including expectations of future eventsnew information. The financial statement areas that are believed to be reasonable under the circumstances. In the future, actual experience may differ from theserequire significant estimates and assumptions.

The effect of a change in an accounting estimate is recognized prospectively by including it in profit or loss in the period of the change, if the change affects that period only; or in the period of the change and future periods, if the change affects both.

Information about critical judgments in applying accounting policies that have the most significant risk of causing material adjustment to the carrying amounts of assets and liabilities recognized in the consolidated annual financial statements within the next financial year are discussed below:as follows:

Decommissioning liability

DecommissioningThe Company recognizes decommissioning liabilities have been recognized based onfor its exploration and evaluation assets and property and equipment. Measurement of the Company’s internal estimates. Assumptions, based on the current economic environment, have been made which management believes are a reasonable basis upon which to estimate the future liability. Thesedecommissioning liabilities involves estimates take into account any material changesand judgements as to the assumptions that occur when reviewed regularly by management. Estimates are reviewed at least annuallycost and are based ontiming of incurrence of future decommissioning programs. It also involves assessment of appropriate discount rates, rates of inflation applicable to future costs and the rate used to measure the accretion charge for each reporting period. Measurement of the liability also reflects current regulatory requirements. Significant changes in estimates of contaminationengineering methodologies as well as current and restoration techniques will result in changes to provisions from period to period.expected future environmental legislation and standards. Actual decommissioning costs will ultimately depend on future market prices for the decommissioning costs which will reflect the market conditions at the time the decommissioning costs are actually incurred. The final cost of the currently recognized decommissioning provisions may be higher or lower than currently provided for.

Exploration and evaluation expenditureexpenditures

The application of the Company’s accounting policy for exploration and evaluation expenditureexpenditures requires judgment in determining whether it is likely that future economic benefits will flow to the Company, which is based on assumptions about future events or circumstances. Estimates and assumptions made may change if new information becomes available. If, after the expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, the amount capitalized is written off in profit or loss in the period in which the new information becomes available.

Income taxes

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The Company recognizes the net future tax benefit related to deferred tax assets to the extent that it is probable that the deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability of deferred tax assets requires the Company to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws in each jurisdiction. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Company to realize the net deferred tax assets recorded at the reporting date could be impacted. Additionally, future changes in tax laws in the jurisdictions in which the Company operates could limit the ability of the Company to obtain tax deductions in future periods. All tax filings are subject to audit and potential reassessment. Accordingly, the actual income tax liability may differ significantly from the estimated and recorded amounts.

Share-based payment transactions

The Company measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date at which they are granted. EstimatingManagement uses judgment to determine the most appropriate valuation model to estimate the fair value for share-based payment transactions requires determining the most appropriate valuation model, which is dependent on the terms and conditions of the grant. This estimate also requires determining the most appropriatetransactions. The inputs to the valuation model, including the expected life of the share option, volatility and dividend yield.yield, require judgment for determination.

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Financial contract liability

The application of the Company’s accounting policy for financial liabilities requires the Company to adjust the carrying amounts of the financial liabilities in the event it revises its payments or receipts to reflect actual and revised estimated cash flows. The Company’s financial contract liability was originally recognized at fair value using the effective interest method which ensures that any interest expense over the period of repayment is at a constant rate on the balance of the liability carried in the balance sheet. Effective June 30, 2014, the Company’s financial contract liability was reduced by the residual reserve value of its working interest in the wellbores at September 30, 2016.

At December 31, 2013, the balance of2015, the financial contract liability was revisedadjusted to reflect actual and revised estimated cash flows resulting in a gain in financial contract liability of $1,268,000. The revisions to the actual and revised cash flows resulted from i) downward revisions in estimated future net revenue from the 2013 sale of ethane in Dejour USA due to poor market conditions; ii) delays in the commencement of 2013 drilling operations in Dejour USA, and iii) an industry-standard, interim natural gas marketing contract in Dejour USA which failed to credit the Company with full natural gas liquids recoveries for 2013.

Despite the reduction in the carryingpresent value of the financial contract liabilityamount outstanding at December 31, 2013,year-end, net of the corresponding asset onpresent value of the Company’s balance sheet required no related charge for impairment. This resulted from a successful 2013 drilling program which converted 47 “probable” drilling locations at December 31, 2012 to “proven” as at December 31, 2013.residual reserves of its working interest in the wellbores.

Impairment

A CGU is defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significantManagement applies judgment and interpretations with respect to the integration between assets,in assessing the existence of active markets, similar exposure to market risks, shared infrastructures,impairment and the way in which management monitors the operations. impairment reversal indicators based on various internal and external factors.

The recoverable amounts of CGUs and individual assets have been determined based on the higher of fair value less costs to sell or value-in-use calculations.value-in-use. The key assumptionsestimates the Company usesapplies in estimating future cash flows fordetermining the recoverable amounts areamount normally include anticipated future commodity prices, expected production volumes, and future operating and development costs.costs, and discount rates. Changes to these assumptions will affect the recoverable amounts of CGUs and individual assets and may then require a material adjustment to their related carrying value. At December 31, 2013,2015, the Company has two CGUs in Canada (Drake/Woodrush and Saddle Hills) and one CGU in the United States (Kokopelli).

Financial instrumentinstruments

When estimating the fair value of financial instruments, the Company uses third-party models and valuation methodologies that utilize observable market data.data where available. In addition to market information, the Company incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk.

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Reserves

The estimate of reserves is used in forecasting the recoverability and economic viability of the Company’s oil and gas properties, and in the depletion and impairment calculations. The process of estimating reserves is complex and requires significant interpretation and judgment. It is affected by economic conditions, production, operating and development activities, and is performed using available geological, geophysical, engineering, and economic data. Reserves are evaluated at least annually by the Company’s independent reserve evaluators and updates to those reserves, if any, are estimated internally. Future development costs are estimated using assumptions as to the number of wells required to produce the commercial reserves, the cost of such wells and associated production facilities and other capital costs.

FUTURE ACCOUNTING PRONOUNCEMENTS

Certain pronouncements were issued by the International Accounting Standards Board (“IASB”)“IASB” or the International Financial Reporting Interpretations Committee (“IFRIC”)“IFRIC” that are mandatory for accounting periods beginning after January 1, 20142016 or later periods.

The following new accounting standards, amendments to accounting standards and interpretations, have not been early adopted in these consolidated annual financial statements. The Company is currently assessing the impact, if any, of this new guidance on the Company’s future results and financial position:

IFRS 9, Financial Instruments is part“Financial Instruments”: In July 2014, the IASB completed the final phase of the IASB's widerits project to replace IAS 39, Financial Instruments: Recognitionthe current standard on the recognition and Measurement.measurement of financial instruments. IFRS 9 retains but simplifiesis now the mixednew standard which sets out the recognition and measurement model and establishes two primary measurement categoriesrequirements for financial assets:instruments and some contracts to buy or sell non-financial items. IFRS 9 provides a single model of classifying and measuring financial assets and liabilities and provides for only two classification categories: amortized cost and fair value. The basisHedge accounting requirements have also been updated in the new standard and are now more aligned with the risk management activities of classification depends on the entity's business model and the contractual cash flow characteristics of the financial asset. The amendments toan entity. IFRS 9 will beis effective as offor annual periods beginning on or after January 1, 2018. The Company will continueEarly adoption is permitted; however, if an entity elects to monitor the changes toapply this standard as they ariseearly, it must disclose that fact and will determineapply all of the impact accordingly.requirements in this standard at the same time.

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IFRS 15, “Revenue from Contract with Customers”. In May 2014, the IASB issued the standard to replace IAS 36, Impairment of Assets was amended in May 2013. This18 “Revenues”, IAS 11 “Construction Contracts”, and related interpretations. The standard reduces the circumstances in which the recoverable amount of CGUs is required to be disclosed and clarify the disclosures required when an impairment loss has been recognizedadopted either retrospectively or reversed in the period. The amendments to IAS 36 are effective as ofusing a modified transition approach for fiscal years beginning on or after January 1, 2014.2018, with earlier adoption permitted.

A. Operating ResultsIFRS 16, “Leases”. In January 2016, the IASB issued the standard to replace IAS 17 “Leases”. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted.

The Company’s annual audited Consolidated Financial Statements for the year ended December 31, 2013,2015, including 20122014 and 20112013 required comparative information, have been prepared in accordance with IFRS.

All financial information is stated in Canadian dollars, the Company’s presentation currency, unless otherwise noted.

Year ended December 31, 20132015 compared to the year ended December 31, 20122014

For the year ended December 31, 2013,2015, total revenue, before royalties, increaseddecreased by $2,435,000$470,000 or, 35%5%, due to a 35%decline in combined average realized prices. This was offset by a 48% increase in oil and natural gas production overfor the year ended December 31, 2012.on a BOE basis.

The average price received for oil sales decreased by 40% for the year ended December 31, 2015, relative to the prior year. The decrease in fiscal 2013 increasedDXI Energy’s average realized oil price reflected lower benchmark prices in line withCanada and the Edmonton Par oil prices which averaged $93.24 per barrel in fiscal 2013, compared to $86.53 per barrel received in fiscal 2012.rest of the world.

Average oil royalties paid for the year ended December 31, 20132015 were consistent on a percentage basis withlower by 31%, relative to those paid in the year ended December 31, 2012.2014, due to lower average oil prices received in 2015.

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Operating and transportation expenses averaged $26.75 per barrel in fiscal 2013. This represents a decrease of 29% from $37.57 per barrel in fiscal 2012.for the year ended December 31, 2015 were lower, compared to the amount recorded for the year ended December 31, 2014. The decreasedecline in per unit operating and transportation expenses in fiscal 2013 resulted from the non-recurring costs of major workovers on one of the oil producing wells at Woodrush in 2012 and the allocation of fixed operating costs over a higher oil production volume.

The average price received for gas sales increaseddecreased by 58%57% for fiscal 2013,the year ended December 31, 2015, relative to the corresponding period of the prior year. The increasedecrease in Dejour’sDXI Energy’s average realized gas price forreflected lower benchmark prices in both Canada and the current year reflected higher benchmark prices.United States.

Average gas royalties for fiscal 2013the year ended December 31, 2015 were higher comparedlower, relative to those paid in the corresponding period of the prior year. Initiation of gas production from the four new wells at Kokopelli contributedyear ended December 31, 2014, due to the increase in royalties in both periods as the effective rate in Colorado is approximately 50% higher than the lower royalty rates for marginal gas production in British Columbia. Additionally, lower gas royalty rates in 2012 are a result of loweraverage gas prices and gas cost allowance credits under the Province of British Columbia royalty framework.received in 2015.

Operating and transportation expenses averaged $2.06 per mcf in fiscal 2013. This represents a decrease of 24% from $2.72 per mcf in fiscal 2012. The decrease in per unit operating and transportation expenses is duefor the year ended December 31, 2015 were lower, relative to the increaseamount recorded for the year ended December 31, 2014. The decline resulted from lower water disposal costs at Kokopelli in lower-cost Colorado gas production as a percentin 2015 compared with 2014. This decrease was partially offset by the increased costs associated with the reactivation of one of the Company’s total gas production.wells at Drake/Woodrush in February 2015 and higher contractual pipeline transportation costs associated with a new contract signed on November 1, 2014.

4.General and Administrative Expenses37

G&A expenses infor fiscal 20132015 were consistent withlower compared to the amount recorded for fiscal 2012. 2013 G&A includes the cost of a non-recurring severance payment of approximately $280,000 to a former senior officer of the Company. Adjusting for this payment results in a 12%2014. The reduction in G&A fromexpenses for the year ended December 31, 20122015 was due to the year ended December 31, 2013.termination of all salaried employees at the Company’s office in Denver, Colorado as part of the June 30, 2014 sale of a controlling working interest in the Kokopelli project to the Company’s Kokopelli partner and new “Operator” of the project. Also, higher G&A expenses for fiscal 2014 resulted from the non-recurring severance payments associated with the termination of a number of the Company’s service providers in the year.

Year ended December 31, 20122014 compared to the year ended December 31, 20112013

For the year ended December 31, 2012 (“fiscal 2012”)2014, total revenue, before royalties, decreased by $268,000 or, 3%, the Company recorded $6,882,000 in oil and natural gas sales as compared to $8,824,000 in oil and natural gas sales for the year ended December 31, 2011 (“fiscal 2011”). The decrease in gross revenues was due to lowera decline in production. This was offset by higher combined average realized oil and gas prices and lower oil and gas production.prices.

Average oil royalties paid for the year ended December 31, 20122014 were consistent on a percentage basis with those paid in the year ended December 31, 2011.2013.

Operating and transportation expenses averaged $37.57 per barrelfor the year ended December 31, 2014 were consistent with those paid in fiscal 2012. This represents an increase of 103% from $18.49 per barrel in fiscal 2012. The increase in per unit operating and transportation expenses in fiscal 2012 resulted from the non-recurring costs of major workovers on one of the oil producing wells at Woodrush in 2012 and higher waterflood implementation expenses.year ended December 31, 2013.

The average price received for gas sales decreasedincreased by 29% for fiscal 2012, relative to the corresponding period of the prior year. The decrease in Dejour’s average realized gas price for the current year reflected lower benchmark prices.

Average gas royalties for fiscal 2012 were lower compared to the corresponding period of the prior year. Substantial reduction in natural gas prices in 2012 resulted in lower gas royalties.

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Operating and transportation expenses averaged $2.72 per mcf in fiscal 2012. This represents an increase of 20% from $2.26 per mcf in fiscal 2011. The increase in per unit operating and transportation expenses is due to the allocation of fixed operating costs over a lower gas production volume.

4.General and Administrative Expenses

General and administrative expenses for fiscal 2012 decreased to $3,433,000 from $4,042,000 for fiscal 2011. The Board and management’s decision to not pay a bonus to employees34% for the year ended December 31, 20122014, relative to the prior year. The increase in DXI Energy’s average realized gas price reflected higher benchmark prices in both Canada and the inclusion of such a bonusUnited States.

Average gas royalties paid in 2011 accountedthe year ended December 31, 2014 were higher compared to the prior year. The average gas price received in 2014 was comparatively higher than the prices received in 2013. This resulted in higher royalty rates for much ofmarginal gas production in 2014.

Average operating and transportation expenses paid for the difference. Further, 2011 included non-recurring professional feesyear ended December 31, 2014 were higher compared to the prior year. The increase resulted from the costs associated with the required conversionworkover of one of the gas producing wells at Drake/Woodrush, the “start-up” costs related to the International Financial Reporting Standards (IFRS).acquisition of certain natural gas producing assets and related production facilities adjacent to the Drake/Woodrush oilfield, and higher contractual pipeline transportation costs in 2014 in Canada. Further, in Q4 2014, the Company incurred a repair to one of the Company’s two compressor facilities which also contributed to an increase in the operating and transportation expenses.

G&A expenses in fiscal 2014 were consistent with the amount recorded for fiscal 2013. G&A expenses included the cost of non-recurring severance payments of approximately $306,000 associated with the termination of a number of the Company’s service providers in the 2^nd half of 2014. Adjusting for these payments results in a 6% reduction in G&A expenses from the year ended December 31, 2013 to the year ended December 31, 2014.

Financial Instruments and Risk Management

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, bank line of credit loan facility, and accounts payable and accrued liabilities.liabilities, and current portion of loans from related parties. Management has determined that the fair value of these financial instruments approximates their carrying values due to their immediate or short-term maturity. Net smelter royalties and related rights to earn or relinquish interests in mineral properties constitute derivative instruments. No value or discounts have been assigned to such instruments as there is no reliable basis to determine fair value until properties are in development or production and reserves have been determined.

From time to time, the Company enters into derivative contracts such as forwards, futures and swaps in an effort to mitigate the effects of volatile commodity prices and protect cash flows to enable funding of its exploration and development programs. Commodity prices can fluctuate due to political events, meteorological conditions, disruptions in supply and changes in demand.

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The primary risks and how the Company mitigates them are disclosed inItem 11 – Quantitative and Qualitative Disclosures About Market Risk, below.

Going Concern, Bank Credit Facility and Loan FacilityLoans from Related Parties

The financial statements were prepared on a going concern basis. The going concern basis assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business. As at December 31, 2013, the Company has a working capital deficiency of $8.9 million and accumulated deficit of $90.8 million. Of the $8.9 million deficiency, only $1.24 million is represented by obligations due within one year in the normal course of business. See WORKING CAPITAL POSITION herein.

On March 12, 2015, as amended on May 6, 2015, June 22, 2015, September 28, 2013, DEAL signed2015 and November 18, 2015, the Company issued a new “Commitment Letter” withpromissory note for $4,500,000 to Hodgkinson Equities Corp. (“HEC”), a private company controlled by the Bank to renew its $5.95 million (December 31, 2012 - $6.0 million) revolving operating demand loan underCEO of the following terms and conditions:

Collateral for Credit Facilities “A” and “B” (the “Credit Facilities”) is provided by a $10.0 million first floating charge over all the assets of DEAL,Dejour USA and a general assignment of DEAL’s book debts, a $10.0 million debenture with a first floating charge over all the assets ofnegative pledge by the Company and an unlimited guarantee provided by Dejour USA. On June 5, 2013, DEAL renewed the Credit Facilities with the Bank and the maximum amount of Credit Facility “A” was reducednot to $3.5 million. On June 19, 2013, Credit Facility “B” was repaid in full. Further, on December 16, 2013further encumber its Canadian oil and February 18, 2014, DEAL renewed the Credit Facility “A” with the Bank and contracted to utilize $600,000 of the $3.5 million to fund the proposed acquisition of certain producing natural gas properties in Canada until March 31, 2014. The acquisition closed on March 26, 2014. Effective March 1, 2014, the Credit Facility reduces by $100,000 per month. The next annual review is scheduled on or before May 1, 2014.

Under the terms of the Credit Facilities, DEAL is required to maintain a working capital ratio of greater than 1:1 at all times. The working capital ratio is defined as the ratio of (i) current assets (including any undrawn and authorized availability under the Credit Facilities) less unrealized hedging gains to (ii) current liabilities (excluding the current portion of outstanding balances of the facility) less unrealized hedging losses. As at December 31, 2013, DEAL was in compliance with its working capital ratio requirement.

On June 19, 2013, the Company borrowed $3.5 million (“Loan Facility”) from a Canadian institutional lender (“Lender”). The Loan Facilitywithout HEC’s prior approval. It bears interest at 14%, payable monthly, and matures on December 14, 2014.the Canadian prime rate plus 5% per annum. The principal isand interest was repayable any time after December 18, 2013 without penalty. Securityby the earlier of (i) within 10 business days of receipt of written demand from HEC for the Loan Facility is comprised of a First Deed of Trust on certainrepayment and (ii) June 10, 2015 or such later date to which the term of the Company’s U.S. oil and gas interests, including a general security agreement, a second mortgage onpromissory note may be extended. On May 6, 2015, the Company’s Canadian properties, and the guarantydue date of the loan was extended to September 30, 2015. On September 28, 2015, the due date of the loan was further extended to December 31, 2015. On November 18, 2015, the Company and Dejour USA.

As partialextended the due date of the loan from December 31, 2015 to November 30, 2018. In consideration for providing the Loan Facility,extension, the Company issued the Lender 7,291,667HEC 9,000,000 Warrants. Each Warrant entitles the holder to acquire one common share at a price of $0.24C$0.45/US$ 0.35 per share any time prior to June 18, 2015. If the Company issues any common shares at a price per share less than $0.24 (the “Issue Price”) any time until December 18, 2013, then the exercise price of the Warrants would automatically be reduced to the higher of (i) the Issue Price and (ii) $0.20.4, 2020. Shares acquired through the exercise of Warrants prior to October 18, 2013April 5, 2016 are restricted from sale through the facilities of the Canadian stock exchange.

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The Company’s ability to continue as a going concernexchanges for four months. In the event of default, all the indebtedness secured by the promissory note become due and payable and the interest rate is dependent upon attaining profitable operations and obtaining sufficient financing to meet obligations and continue exploration and development activities. There is no assurance that these activities will be successful. These material uncertainties cast substantial doubt upon the Company’s ability to continue as a going concern. The related consolidated financial statements do not reflect the adjustmentsimmediately increased to the carrying values of assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used that would be necessary if the going concern assumptions were not appropriate.

Cash Balances

The Company had cash and cash equivalents of $505,000 asCanadian prime rate plus 8.5% per annum. As at December 31, 2013.2015, the maximum $4.5 million had been advanced to the Company. On February 19, 2016, the Company rescinded the negative pledge security agreement and issued a first mortgage in favour of HEC on its Canadian oil and gas properties. The first mortgage security so issued ranks “pari passu” with HVI’s first mortgage security interest.

On June 22, 2015, as amended on September 28, 2015 and November 18, 2015, the Company issued a promissory note for $2,000,000 to Hodgkinson Ventures Inc. (“HVI”), a private company associated with the CEO of the Company, on a “pari passu” basis with the loan from HEC. The promissory note is secured by all assets of Dejour USA and a negative pledge by the Company not to further encumber its Canadian oil and gas properties without HVI’s prior approval. It bears interest at the Canadian prime rate plus 5% per annum. The principal and interest was repayable on or before September 30, 2015. On September 28, 2015, the due date of the loan was extended to December 31, 2015. On November 18, 2015, the Company extended the due date of the loan from December 31, 2015 to November 30, 2018. In consideration for the extension, the Company issued HVI 4,000,000 Warrants. Each Warrant entitles the holder to acquire one common share at a price of C$0.45/US$ 0.35 per share any time prior to December 4, 2020. Shares acquired through the exercise of Warrants prior to April 5, 2016 are restricted from sale through the facilities of the stock exchanges for four months. In the event of default, all the indebtedness secured by the promissory note become due and payable and the interest rate is immediately increased to the Canadian prime rate plus 8.5% per annum. As at December 31, 2015, the maximum $2.0 million had been advanced to the Company. On February 19, 2016, the Company rescinded the negative pledge security agreement and issued a first mortgage in favour of HVI on its Canadian oil and gas properties. The first mortgage security so issued ranks “pari passu” with HEC’s first mortgage security interest.

On September 15, 2015, as amended on January 11, 2016 and March 31, 2016, the Company issued a grid promissory note of up to $1,000,000 to a director and officer of the Company and his spouse. The promissory note bears interest at 12% per annum. The principal and interest accrued on the loan were repayable on or before December 31, 2015. On January 11, 2016, the Company issued an additional grid promissory note of up to $200,000 to a director and officer of the Company and his spouse and the due date of the loan was extended to March 31, 2016. On March 31, 2016, the due date of the loan was further extended to September 30, 2016. As at December 31, 2015, $1,000,000 had been advanced to the Company.

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Financial Contract Liability

On December 31, 2012, Dejour USA entered into a financial contract with a U.S. oil and gas drilling fund (“Drilling Fund”), that is associated through a relationship with a former director to fund the drilling of the Company, to drill up to three wells and completethe completion of up to four wells (“the Tranche 1 Wells”) in the State of Colorado. By agreement:The Drilling Fund contributed US$6.5 million cash to earn working interests in production from the wellbores ranging from 55.56% to 77.78% before payout and 44.44% to 58.33% after payout. This amount was subsequently increased by US$500,000 to US$7,000,000 with the Company’s consent.

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Dejour USA considersto purchase its working interests in the wellbores for cash in September 2016, 36-months after the final well in the 4-well program is placed in production. The repurchase price is based on a predetermined formula which ensures the Drilling Fund earns a minimum return, compounded annually and applied on a monthly basis, on 75% of its original US$7,000,000 investment over the 36-month period. Accordingly, the Company considered the transaction to be a financial contract liability as the risks and rewards of ownership havewere not been substantially transferred at the Agreement date. Onto the Drilling Fund financing advance,and, on December 31, 2012, the Company increasedrecorded the transaction in its accounts by increasing property and equipment and financial contract liability by $6.5 million (US$6.5 million). DuringUS$6,500,000 on its balance sheet. This amount was subsequently increased to US$7,000,000.

On June 30, 2014, the year ended December 31, 2013, the Company increased property and equipment and financial contract liability by $443,000 (US$417,000) of the incremental US$500,000 advance received in the year. On initial recognition, the Company imputed its borrowing cost of 8.4% based on the estimated timingwas amended and amount of operating profit using the independent reserve engineer’s estimated future cash flows for the Drilling FundsFund agreed to retain its working interest in the Tranche 1 Wells. Subsequentwells as at September 30, 2016, should it exercise its right to initial measurementrequire Dejour USA to pay the minimum return calculated in accordance with the provisions of the contract. In determining the minimum return to be paid, the Drilling Fund agreed to deduct the residual reserve value of its working interest in the 4 wellbores at September 30, 2016. The parties also agreed to have a third party engineering firm calculate the residual value of the reserves in accordance with industry accepted valuation standards.

Finally, the parties agreed to limit the cash consideration to be paid by Dejour USA, should it be required to pay the minimum return provided for in the December 31, 2012 contract to US$3,000,000. Additional consideration, if any, may be paid by Dejour USA by an assignment of a working interest in certain proven assets at a jointly owned oil and gas property in Colorado applying an industry-standard valuation approach.

The June 30, 2014 amendment transferred the risks of ownership of the 4 wellbores back to the Drilling Fund and the financial contract liability will be increased bywas adjusted to reflect the imputed interest expense and decreased by the Drilling Fund’s net operating profit from the Tranche 1 Wells. Any changes in the estimated timing and amountpresent value of the net operating profit cash flows will be discounted at the initial imputed interest rate with any change in the recognized liability recognized as a gain (loss) in the period of change. The Company has estimated the current portion of the obligation based on the expected net operating profit to be paidamount owing to the Drilling Fund inunder the next twelve months.financial contract at September 30, 2016 ($7,843,000), net of the present value of the residual reserves ($636,000), or $7,207,000, as follows:

The estimated reductionincrease in the financial contract liability is estimatedwas due to be:(1) the significant decline in the value of residual reserves and (2) the upward movement of foreign exchange rate at the year-end.

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Working Capital Position

Working capital is defined as current assets less current liabilities.

As at December 31, 2013,2015, the Company had a working capital deficit of $8.9$10.3 million. Excluding the non-cash warrant liability of $0.3 million related to the fair value of US$ denominated warrants issued in previous equity financings, the non-cash derivative liability of $0.3 million related to the fair value of warrants issued in loan facility closed in June 2013 and the current portion of financial contract liability of $1.2 million, the adjusted working capital deficit was $7.0$9.1 million. Of this amount, $7.2 million is represented by a financial contract liability of Dejour USA, which is due on September 30, 2016. The majoritymaximum cash component due in full settlement of the working capital deficit relates tofinancial contract liability is US$3.0 million. Our independent auditors have included an explanatory paragraph in their report on our consolidated financial statements for the $2.9 million outstanding bank line of credit, with a $0.6 million credit limit remaining and the $2.9 million outstanding loan facility.

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The bank line of credit is classified as current liabilities because it is a demand loan, subject to periodic review by the lender. Atyear ended December 31, 2013, Dejour USA was in default of its working capital ratio covenant with the Canadian institutional lender (“Lender”) who provided the loan facility. As2015 that describes uncertainties that cast substantial doubt about our ability to continue as a result, the loan facility is due upon demand and classified as current liabilities. The Lender has not demanded repayment as at December 31, 2013.

The Company expects to fund future capital requirements and expenditures through the use of a combination of cash provided by operating activities and bank debt supplemented by new equity or debt offerings, as required.going concern.

Capital Resources

a)  Canada

During 2013,In 2015, the Company incurred $31,000 of its consolidated capital expenditures of $2$1.0 million at Drake/Woodrushto complete and tie into production the 2 infill wells that were recently drilled in northeasternNortheastern, British Columbia. These capital expenditures were funded by cash on hand and an operating linethe loans from the companies associated with a director and officer of creditthe Company.

In 2015, the Company paid $4.5 million for the ongoing Kokopelli development program in Colorado and it is related to the drilling, casing and completion of $3,500,000 provided by DEAL’s Canadian bank.

eight natural gas wells. These wells were tied into production in the fourth quarter of 2015. The Company has developed a capital budget of $2,500,000 to further develop the natural gas potential of its Drake/Woodrush properties. It is expectedfunded this program if implemented, will be funded by one, orthrough the use of a combination of cash on hand and the following sources:loans from the companies associated with a director and officer of the Company.

b)  United StatesNone.

The Companygeneral outlook for crude oil prices will be tied primarily to the supply response to the current price environment and partners drilledthe pace of growth of the global economy. Overall, crude oil price volatility and completed 4 Williams Fork formation wells ata modest price improvement are expected in 2016. Slower global supply growth, combined with annual increases in demand growth, should support prices in the Company’s core Kokopellisecond half of 2016, constrained by the need to draw down surplus crude oil inventories and anticipated re-entry of Iranian crude oil into markets. Also, slower supply growth from North American producers is anticipated as a result of the significant reductions in capital spending.

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During 2015, natural gas property in the Piceance Basin in 2013. This drilling program increased the number of “proved undeveloped” drilling locations from 92 locations to 139 locations, as determined by the Company’s independent reservoir engineers in a report dated January 1, 2014.

The Company has monitored production from the 4 initial wells since the fourth well was placed on production in September 2013. The Company is now seeking a joint venture partner to purchase an interest in Kokopelli, provide a negotiated amount of financing to further develop “Phase II” of Kokopelli, and, initially pay for the Company’s share of drilling and completion costs up to a predetermined contractual maximum. Following completion of this initial capital expenditure, the Company will be responsible for its working interest share of remaining capital costs to fully develop Kokopelli.

2012

On December 31, 2012, the Company closed a US$6,500,000 financing with a Denver-based drilling fund to partially fund the initial development of the Company’s “Kokopelli” project in the eastern portion of the Piceance Basin. The Drilling Fund also committed to invest a further US$500,000 in the four wells for a total of US$7.0 million. As at December 31, 2013, US$417,000 of the incremental US$500,000 has been invested for a total of US$6.9 million. Under the terms of the industry-standard agreement, the Company will earn a “before-payout” (‘BPO’) working interest of 10% to 14% and an “after payout” (‘APO’) working interest of 28% to 39%. In September 2013, Dejour USA signed an amendment with the Drilling Fund and agreed to earn the revised “before payout” working interest of 15.88% to 22.23% and revised “after payout” working interest of 29.77% to 41.67% in the net operating profits from the Tranche 1 Wells based on the actual cash invested in the drilling program.

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The agreement with the Drilling Fund provides for an additional two tranches of drilling under the following terms and conditions:

C. Research and Development, Patents and Licenses, etc.

None.

D.Trend Information

During mid-December, 2013, the “polar vortex” resulted in recordprices were relatively low temperatures for most of Canada2015 because of excess supply and 2/3rds ofmild weather forecast.

Warmer weather is expected to reduce residential and commercial demand, while coal-to-gas substitution in the United States. High demand forpower sector is expected to continue. As a result, natural gas drew working gas in storage inprices are anticipated to remain weak through the U.S. down to well under the five year average. At the endfirst half of Q1 2014, working gas in storage was approximately 826 Bcf, roughly 849 Bcf less than the same period in 2013 and 997 Bcf off the five-year average.2016.

The Company has no material undisclosed off-balance sheet arrangements that have or are reasonably likely to have, a current or future effect on our results of operations or financial condition at December 31, 2013.2015.

As of December 31, 2013,2015, and in the normal course of business we have obligations to make future payments, representing contracts and other commitments that are known and committed.

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The Company seeks safe harbor for our forward-looking statements contained in Items 5.E and F. See the heading “Cautionary Note Regarding Forward-Looking Statements” above.

The following table sets forth all current directors and executive officers of DejourDXI Energy as of the date of this annual report on Form 20-F, with each position and office held by them in the Company and the period of service as such.

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